Condensate Bank Characterization from Well Test Data and Fluid PVT Properties
- Manijeh Bozorgzadeh (Imperial College) | Alain C. Gringarten (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 2006
- Document Type
- Journal Paper
- 596 - 611
- 2006. Society of Petroleum Engineers
- 5.2 Fluid Characterization, 5.2 Reservoir Fluid Dynamics, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.5.1 Fracture design and containment, 5.1.5 Geologic Modeling, 2.2.2 Perforating, 5.4.3 Gas Cycling, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 7.5.3 Professional Registration/Cetification, 4.3.4 Scale, 5.6.4 Drillstem/Well Testing, 5.5.8 History Matching, 5.8.8 Gas-condensate reservoirs, 5.1.2 Faults and Fracture Characterisation, 5.2.2 Fluid Modeling, Equations of State
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Published well-test analyses in gas/condensate reservoirs in which the pressure has dropped below the dewpoint are usually based on a two- or three-region radial composite well-test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas/condensate-specific results from well-test analysis are the mobility and storativity ratios between the regions and the condensate-bank radius. For a given region, however, well-test analysis cannot uncouple the storativity ratio from the region radius, and the storativity ratio must be estimated independently to obtain the correct bank radius. In most cases, the storativity ratio is calculated incorrectly, which explains why condensate bank radii from well-test analysis often differ greatly from those obtained by numerical compositional simulation.
In this study, a new method is introduced to estimate the storativity ratios between the different zones from buildup data when the saturation profile does not change during the buildup. Application of the method is illustrated with the analysis of a transient-pressure test in a gas/condensate field in the North Sea. The analysis uses single-phase pseudopressures and two- and three-zone radial composite well-test interpretation models to yield the condensate-bank radius. The calculated condensate-bank radius is validated by verifying analytical well-test analyses with compositional simulations that include capillary number and inertia effects.
Introduction and Background
When the bottomhole flowing pressure falls below the dewpoint in a gas/condensate reservoir, retrograde condensation occurs, and a bank of condensate builds up around the producing well. This process creates concentric zones with different liquid saturations around the well (Fevang and Whitson 1996; Kniazeff and Nvaille 1965; Economides et al. 1987). The zone away from the well, where the reservoir pressure is still above the dewpoint, contains the original gas. The condensate bank around the wellbore contains two phases, reservoir gas and liquid condensate, and has a reduced gas mobility, except in the immediate vicinity of the well at high production rates, where the relative permeability to gas is greater than in the bank because of capillary number effects (Danesh et al. 1994; Boom et al. 1995; Henderson et al. 1998; Mott et al. 1999).
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